Coal-fired power station and method for operating the coal-fired power station

ABSTRACT

In a method for operating and controlling/regulating a power station comprising a coal-fired steam generator ( 11 ), the steam generator ( 11 ) of which is rated for the steam parameters achievable by the heat transfer onto the steam mass flow upon coal firing in the steam generator ( 11 ) carried out using combustion air, a solution is to be created, which enables the operation of coal-fired power stations rated for air operation utilizing a firing of the fuel carried out according to the oxy-fuel process in the firing chamber of the steam generator of the coal-fired power station. This is achieved in that a firing of the fuel containing coal is carried out in the steam generator ( 11 ) according to the oxy-fuel process utilizing approximately pure oxygen containing more than 95% by volume, and recirculated flue gas containing a high amount of CO 2 , such that the mass flows of all fuel flows supplied to the coal-fired burners ( 10 ) and to the steam generator ( 11 ), and the combustion gas, carrier gas, and process gas flows from the combustion oxygen and/or recirculated flue gas are configured and adjusted to each other with respect to the respective composition ratio thereof of oxygen and/or flue gas such that the heat transfer occurring in the steam generator by means of flame radiation, gas radiation, and convection onto the steam mass flow is maintained equal overall in the steam/water cycle as compared to air combustion, in particular, that the same steam parameters are obtained.

The invention relates to a method for operating and for controlling apower station which comprises a coal-fired steam generator, whose steamgenerator is designed for steam parameters which can be achieved forcoal combustion, which is carried out with combustion air, in the steamgenerator by heat transfer to the steam mass flow.

The invention furthermore relates to a coal-fired power station having acoal-fired steam generator whose steam generator is designed for steamparameters which can be achieved for coal combustion, which is carriedout with combustion air, in the steam generator by heat transfer to thesteam mass flow.

In order to make it possible to greatly reduce the CO₂ emissions whenelectricity is generated from fossil fuels in the future, the twoconcepts described in the following text are currently being developed,which can be used in conventionally designed coal-dust-fired powerstations (hard coal or brown coal) with large steam generators, andwhich are intended to be commercially available for future power stationgenerations.

1. Post-combustion CO₂ capture by downstream CO₂ flue gas washing.

In this case, the CO₂ which is present in a small concentration (˜13% byvolume) in the flue gas is absorbed with washing solutions in a packedcolumn with energy being released, and is desorbed in a second column,with energy being supplied. The additional energy supply which isrequired for desorption (generally in the form of energy supplied fromsteam tapped off from the medium-pressure turbine) leads to decreases inefficiency of 10-12 percentage points in comparison to power stationswithout such CO₂ capture. This technology has the advantage, inter alia,that the method is carried out after the combustion process and has noreactions on the steam generator, thus allowing existing power stationsto be retrofitted. The disadvantages include the large amount of spacerequired for the flue gas washer and the high energy consumptionwhich—in the case of possible retrofitting—results in a large amount ofmodification effort in the area of the steam circuit and of the turbine.

2. Oxyfuel combustion with direct CO₂ compression

In the oxyfuel process, the CO₂ concentration in the flue gas is greatlyincreased by using a mixture of fed-back flue gas and virtually pureoxygen instead of air for combustion of the coal. In this case, inparticular, the sealing of the power station installation—which forsafety reasons is still operated at a slightly reduced pressure—with allits components, the purity of the oxygen taken from an air separationunit (ASU), the quality of the flue gas cleaning installations(denitrification (DeNOx), desulfurization (DeSOx), dust removal) and theprocess control—particularly the location of the flue gas feed back (forexample the points/locations 1-6 in FIG. 1)—are the critical factors forthe purity of the CO₂ which leaves the process after flue gas drying(condensation of the water by cooling). In this case, the CO₂concentration should in any case be sufficiently high, and thehazardous-substance load so low, that the CO₂ can be compressed directlyand be supplied for storage. The advantage of this concept is that boththe steam generator as well as the steam circuit and the turbine design,which are designed for a conventional air mode, do not fundamentallydiffer from those which are designed for the oxyfuel mode. In addition,the efficiency reductions in this process are 8-10 percentage pointslower than in the case of downstream CO₂ flue gas washing, in comparisonto power stations without CO₂ capture. These reductions are contributedto significantly by the electrical energy required for the airseparation unit that has to be installed itself (>60% of the reductions)as well as the additional flue gas compression (>25% of the reductions).The proportion of the other units required in comparison to conventionalcoal-fired power stations in the additional energy requirement is <15%.

In order now to provide the value stability of investments that havealready been made in newly built coal-fired power stations with thegreatest possible flexibility in terms of future developments related toCO₂ capture which may still have to be retrofitted, it is necessary forpresent newly built power stations to be able to (continue to) operatein the future by conversion to the oxyfuel mode, and as low-CO₂ powerstations. However, it is also desirable for older, already existingcoal-fired power stations to be equipped with CO₂ capturecost-effectively, that is to say with as little investment cost aspossible and with as little loss of efficiency as possible, and to allowthem to be converted to oxyfuel operation with CO₂ capture.

The invention is therefore based on the object of providing a solutionwhich allows coal-fired power stations designed for air operation to beoperated with combustion of the fuel based on the oxyfuel process in thefurnace area of the steam generator of the coal-fired power station.

In one method of the type mentioned initially, this object is achievedaccording to the invention in that combustion of the fuel, whichcontains carbon, is carried out in the steam generator on the basis ofthe oxyfuel process with approximately pure oxygen, which contains morethan 95% by volume of O₂, and recirculated flue gas with a high CO₂content, such that the mass flows of all the fuel flows as well ascombustion gas flows, feed gas flows and process gas flows which aresupplied to the coal-burners and to the steam generator are formed fromcombustion oxygen and/or recirculated flue gas in their respectivecomposition ratio of oxygen and/or flue gas, and are matched to oneanother, such that the heat transfer which takes place in the steamgenerator by flame radiation, gas radiation and convection to the steammass flow in the steam/water circuit of the steam generator is kept thesame overall in comparison to the air combustion, in particular with thesame steam parameters being maintained.

In a power station of the type referred to in more detail initially, theabove-mentioned object is achieved according to the invention in ananalogous manner in that combustion of the fuel, which contains carbon,is carried out in the steam generator on the basis of the oxyfuelprocess with approximately pure oxygen, which contains more than 95% byvolume of O₂, and recirculated flue gas with a high CO₂ content, suchthat the mass flows of all the fuel flows as well as combustion gasflows, feed gas flows and process gas flows which are supplied to thecoal-burners and to the steam generator are formed from combustionoxygen and/or recirculated flue gas in their respective compositionratio of oxygen and/or flue gas, and are matched to one another, suchthat the heat transfer which takes place in the steam generator by flameradiation, gas radiation and convection to the steam mass flow in thesteam/water circuit of the steam generator remains the same overall incomparison to the air combustion, in particular with the resultant steamparameters being the same.

Advantageous developments and expedient refinements of the invention arespecified in the respective dependent claims.

The invention means that a coal-fired power station designed forcombustion with air can also be operated without any problems as aCO₂-free or low-CO₂ power station operating on the basis of the oxyfuelprocess with recirculated flue gas, and can be converted to orretrofitted with the oxyfuel process or oxyfuel mode. In a power stationsuch as this, the burners are then operated with a supply of pure oxygenof with >95% by volume of O₂, or a mixture of pure oxygen andrecirculated flue gas with a high CO₂ content.

In order to allow a conventional power station, designed for the airmode, to be operated in the oxyfuel mode, flue gas which is createdduring the combustion process is fed back, that is to say recirculated,into the burner and the burner or furnace area. In order to achieve thesame steam parameters as during the air mode in the oxyfuel mode, it ispossible, according to one refinement of the invention, for treatedand/or untreated flue gas to be fed back in a recirculating manner tothe steam generator. “Untreated” flue gas means flue gas which is tappedoff in the flue gas path after the steam generator for recirculationbefore any flue gas treatment is carried out in the flue gas path, forexample by an electrical filter, a flue gas desulfurization installationor a flue gas drier. The process of passing through heat displacementsystems or elements by means of which energy is simply extracted fromthe flue gas does not mean that the flue gas can then be regarded ashaving been treated. The exemplary embodiment illustrated in FIG. 1shows possible points and locations for tapping off untreated flue gas,provided with the reference symbols 1, 2 and 3. The term “treated” fluegas means a treatment which changes the flue gas composition. Possiblepoints or locations for tapping off treated flue gas for recirculationare identified by the reference symbols 4, 5 and 6 in FIG. 1.

Since modern power stations in particular are expediently intended to becapable of subsequent conversion to the oxyfuel mode, the inventionfurthermore provides that an existing power station, in particular aso-called 600° C. power station, is retrofitted with the method asclaimed in claim 1 or 2.

In order to achieve the same steam parameters in the oxyfuel mode as inthe air mode, it is expedient according to a further refinement of theinvention that the recirculation rate of the flue gas is 65% to 80%, inparticular 74% to 78%.

A power station designed for the air mode can be operated in the oxyfuelmode with particularly minor conversion or modification effort if theflue gas is tapped off after desulfurization (DeSOx) or after a flue gasdesulfurization (DeSOx) installation or a flue gas cooler, which isinstalled in particular additionally and/or subsequently, forrecirculation, as the invention likewise provides.

According to one refinement of the invention, it is also a majoradvantage for the flue gas to be tapped off after a flue gascondensation drier in the flow direction.

Because of the high proportion of CO₂ in the flue gas, it is alsoexpedient in the oxyfuel mode for quicklime (CaO) to be used asabsorbent in the flue gas DeSOx installation.

In one refinement of the power station according to the invention, theinvention provides that a heat displacement system is installed betweena suction draft and desulfurization or a desulfurization installation.This makes it possible to influence the thermal balance of therecirculating flue gas flow, as well as the temperature of therecirculated flue gas, via energy removal.

In order to allow the temperature of the flue gas or else that of theoxygen which is supplied to the steam generator after air separation inan air separation unit to be influenced in an advantageous manner, thepower station according to the invention is, finally, distinguished inthat the flue gas channel has a bypass line, which is routed inparticular parallel to an air preheater (LUVO) and has a gas/gas heatexchanger arranged therein, after a denitrification (DeNOx) device inthe flow direction.

It is self-evident that the features mentioned above and those which arestill to be explained in the following text can be used not only in therespectively stated combination but also in other combinations. Thescope of the invention is defined only by the claims.

The invention will be explained in more detail in the following textwith reference to a drawing, in which:

FIG. 1 shows a schematic illustration of a method and installationlayout for the gas and combustion side of a steam generator,

FIG. 2 shows a schematic outline illustration of a method layout for thegas and combustion side of a steam generator,

FIG. 3 shows a schematic outline illustration of a further embodiment ofa method layout on the gas and combustion side of a steam generator,

FIG. 4 shows a schematic outline and section illustration of the designof a steam generator,

FIG. 5 shows a comparison of the temperature profile over the furnaceheight in the radiation part of a steam generator in comparison betweenthe air mode and the oxyfuel mode,

FIG. 6 shows a comparison of the temperature profile in the convectivepart of a steam generator in comparison between the air mode and theoxyfuel mode,

FIG. 7 shows the temperature profile of the water/steam system in theconvective part of a steam generator in comparison between the air modeand the oxyfuel mode,

FIG. 8 shows an illustration in the form of a table of the differencebetween various characteristic values in comparison between the oxyfuelmode and the air mode, on the one hand using metric units and on theother hand percentages,

FIG. 9 shows an illustration in the form of a table of the difference inthe flue gas composition after the electrical filter in comparisonbetween the air mode and the oxyfuel process,

FIG. 10 shows a table of a comparison between the air mode and theoxyfuel mode in respect of different physical characteristics and

FIG. 11 shows an illustration, corresponding to

FIG. 2, with additional details of the gas temperatures in ° C. and ofthe mass flows in kg/s.

The installation additions and modifications will be described in thefollowing text, with reference to FIGS. 1-3, which allow a conventionalcoal-fired power station to be converted to the oxyfuel mode. A methodis also described, on the basis of which the oxyfuel mode can then becarried out in an optimum manner. A special feature of the conversionand of the method is that normal air operation is also still possibleafter conversion. For example, the installation can be safely started inthe air mode before switching to the oxyfuel mode, and with switchingonce again taking place to the air mode, which can be coped with moreeasily (with high efficiency) and with CO₂ emission, before shutdown, inthe event of disturbances in operation, or in the event of aninterruption in the CO₂ storage capability downstream from the powerstation.

FIG. 2 shows a method layout on the gas side of a coal-fired powerstation, on the basis and by means of which the coal-fired power stationcan be operated both in the air mode and in the oxyfuel mode on theburner side. In this case, when the installation is in the air mode, thecombustion air is preheated after induction by the fresh-air fan 7 in aheat displacement system (WVS) 35 (WÜ3) which may be provided. However,this is not provided in all power stations nowadays. After furtherheating in the air preheater (LUVO) 8, the air is split into carrierair, other burner air, and —if present—into a mill circuit flow. Thecarrier air is supplied upstream of the mill to a further fan (primaryfan) 9, whose pressure increase ensures that the coal is removed to theburners 10.

The mill circuit flow is used for heat displacement (WÜ1 and WÜ2) fromthe off-gas to the feed water preheating path. This has a positiveeffect on the overall efficiency of the installation, because a greaterheat flow of the off-gas is used, thus reducing the off-gas losses.Furthermore, it is possible to save tapped-off steam for feed waterpreheating.

After combustion in the steam generator 11, in addition to exchangingheat with the combustion air (LUVO), the flue gas is also subjected tocatalytic denitrification 12 in order to reduce the NOx emissions, dustremoval 13 and desulfurization 14, in order to comply with therespective emission limit values.

In the area of the steam generator 11, the coal is burnt in thecombustion area and a portion of the heat transfer takes place to theworking medium steam/water in the wall heating surfaces of the steamgenerator (mainly by radiation). A convective heat transfer takes placein the subsequent convective heating surfaces to superheater,intermediate superheater and economizer heater surfaces.

During operation of an installation such as this, on the basis of theoxyfuel process, it would now be problematic to use recirculation gas(flue gas) at a high temperature level and flue gas taken beforecompletion of the flue gas cleaning at the points 1-4 shown in FIG. 1,for example, and fed back to the steam generator 11, because of the highdust and/or SO₂/SO₃ content. The increased temperature level incomparison to that when the installation is designed for the air mode,the higher dust and SO₂/SO₃ content and the risk of erosion/corrosionresulting from this to flue gas channels, air channels, suction draftfans, any mill air fans that are present, mill air heat exchangers,mills, burner fittings and boiler materials would necessitate completereplacement of these items, because of the increased risk of wear.Furthermore, the heat technology/connection of the heat exchangers wouldalso have to be completely revised as far as the burner, because of thechange in the temperature levels. Although such conversion is inprinciple possible, it would no longer be possible to subsequentlyoperate the installation (easily) in air mode without furthermodifications/additions. The provision of both operating modes and thecreation/setting of all the items required in this case as well as airchannels and recirculation channels is, however, virtually precluded forretrofit purposes in modern power stations, because of the lack ofavailable space, or is in any case associated with very high technicalcomplexity and financial cost. The risk of increased SO₃ formation inthe flue gas with corresponding enrichment and repeated contact withcatalytically active surfaces in the DeNOx reactor (denitrificationreactor) 12 and LUVO (air preheater) 8 would be impossible to avoid.

For the described reasons, in the case of the oxyfuel mode methodaccording to the invention, described here, the flue gas which isenriched with oxygen as recirculation gas and is used as a substitutefor the combustion air is therefore in one preferred embodiment tappedoff after the desulfurization 14, 15 at the point 5 or after a flue gascooler 16, which has to be additionally installed, at the point 6, inwhich case, of course, mixtures of flue gas fed back at the points to 4or 1 to 5 or one of these points are also possible. The flue gas has avery high purity level at these points 5 and 6 (in respect of dust,SO₂/SO₃ content) and is at a sufficiently low temperature. This ensuresthat, when changing over to the oxyfuel mode, all the existing items andair/flue gas channels can be still be used. All that is needed is toconnect the flue gas return channel 22, 23 to the fresh-air induction 7and to install a valve, which forms as good a seal as possible, forswitching between the oxyfuel mode and the air mode. In the oxyfuelmode, the steam parameters of air operation can then be achieved, as canbe seen from FIGS. 5 to 7. FIG. 5 shows that the temperature profilecurve 43 for the oxyfuel mode 43 provides a good match with the curve 44for the air mode. In addition, in a comparison of the result illustratedin the left-hand part of the figure for oxyfuel operation with the airmode as illustrated in the right-hand part of the figure, FIG. 6likewise shows that essentially the same temperatures can be createdboth on the combustion area side and on the steam side in the oxyfuelmode as the respectively stated temperature values show over the heightof a steam generator 11. It is therefore evident that the heat transferwhich takes place in the steam generator 11 by flame radiation, gasradiation and convection to the steam mass flow in the steam/watercircuit of the steam generator remains at least essentially the sameoverall, in comparison to air combustion, in particular the same steamparameters being maintained. This is also evident from FIG. 7, whichshows that the curve 45 for the air mode and the curve 46 for theoxyfuel mode, which each represent the heat transfer into thewater/steam system over the height of the vaporizer and therefore theheat transfer in the convection path, exhibit essentially the sametemperature profile over the height of the steam generator 11.

It may be necessary to install a heat displacement system (WVS) 16, 35between the suction draft 17 and the desulfurization 14, 15, if theinstallation does not already have this. Further changes relate to thearea of the oxidation in the desulfurization installation 15 and in thedenitrification 12, oxygen preheating 19 and the mill barrier gas 40.

To avoid intervening to a greater extent in the heat technology of thepower station, it is ensured that the heat transfer in the area of thecombustion area 18 and in the area of the downstream convective heatingsurfaces is ensured in the oxyfuel mode as well, in a correspondingmanner to the design for combustion using air. In the method accordingto the invention, this is achieved in that the amount of flue gas whichflows through the convective heating surfaces when the outputtemperature of the combustion area is the same is governed such thatvirtually the same amounts of heat are transferred to the steam, as theworking medium, despite the changed heat transfer conditions (density,flue gas temperature profile, flow rate and heat transfer coefficient)resulting from the combustion of O₂ with flue gas containing CO₂ beingfed back.

The combustion side, that is to say the flue gas/gas side of the steamgenerator 11, is adapted because of the changed flue gascharacteristics, both with respect to the heat content (density, heatcapacity) and heat transfer (changed flow rates, heat transfercoefficients). The aim is that the water/steam circuit should remain atleast substantially unchanged. In the case of the oxyfuel mode (oxyfuelcase), the magnitude of the total amount of recirculated flue gas, thesplit between the various combustion gas, feed gas and process gas flows(burner “air”, mill “air”, over fire “air”, curtain “air”) as well asthe oxygen contents of these gas flows and the total amount of excessoxygen result in new degrees of freedom which are used for adaptation ofthe combustion.

First of all, the total amount of recirculated gas is determined suchthat the heat transfer in the convective heating surfaces corresponds tothe old design data.

As shown in FIG. 8, which figure lists average values of variables whichcharacterize the heat transfer in the convective surfaces, this is donein the oxyfuel case with an amount of recirculated gas which causes aflue gas density which is higher by 38.5% than the air mode, a higherheat transfer (alpha) by radiation (+23%) and convection (+6.8%), a fluegas mass flow increased by 7.8% and a reduction in the mean logarithmictemperature difference by 11.2% or produces these effects. In this case,the recirculation rate of the flue gas is 75.7%. However, this value isdependent on the precise fuel characteristics and the basic design ofthe power station, and can assume values between 65 and 80%. Therecirculation rate means the proportion of the recirculated flue gas inthe total amount of flue gas.

Nowadays, power stations are equipped with low-NOx burners andcombustion systems as a primary measure against nitrogen oxideemissions, which, in addition to the carrier “air” which transports thefuel, have at least one—generally twisted—secondary “air” and, in thecase of a twist-stage burner, furthermore an outer tertiary “air” and aninner core “air” flow. By appropriate choice of the twist andimpulses/impulse ratios of the individual flows, it is possible tooptimally control the combustion of the coal and the NOx emission bycontrol of the oxygen-rich and low-oxygen zones in the flame. A burnersuch as this is therefore able to operate with different gascompositions and therefore offers the capability to adjust thecombustion and temperature profile in a suitable manner in the oxyfuelmode such that analogous amounts of heat are transferred in thecombustion chamber as in the air mode, combustion furthermore takingplace with low levels of hazardous substances.

Furthermore, in the oxyfuel mode, because the flue gas is very largelyfree of nitrogen, virtually no thermal NOx is formed, thus resulting inlower NOx emission (in comparison to the air mode).

The proportion of the recirculated flue gas which is required for theburner in the oxyfuel mode is obtained to a first approximation from therequirement to maintain the impulse flows at the burners in the variousoperating modes.

The impulse flow is given by equation 1:

I_(PG,SG)=n&_(PG,SG)W_(PG,SG)  Equation 1

where

I_(PG,SG) impulse flow of the primary and secondary gases

m_(PG,SG) mass flow of the primary and secondary gases

W_(PG,SG) flow rate of the primary and secondary gases

If the cross section is constant and the impulse flow does not change,then:

$\begin{matrix}{{\overset{.}{m}}_{{PG},{SG}} = {{\overset{.}{m}}_{{PL},{SL}}\sqrt{\frac{\rho_{{PL},{SL}}}{\rho_{{PG},{SG}}}}}} & {{Equation}\mspace{14mu} 2}\end{matrix}$

where

n&_(PF,SG) mass flow of the primary and secondary gases in the oxyfuelmode

n&_(PL,SL) mass flow of the primary and secondary gases in the air mode

p_(PL,SL) density of the primary air and secondary air

p_(PG,SG) density of the recirculated flue gas as a function of thecomposition of the primary and secondary gas.

The component 47 of the burner “air” which is used as a flow element ofthe combustion gas in order to remove the coal from the mill 36 (carriergas) must also be determined corresponding to the equality of theimpulse forces acting on the coal particles.

Whether the impulse flow maintenance at the burner means that thatcarrier gas is able to remove coal from the mill 36 depends on the flowresistance (equation 3), the lift force (equation 4) and the weightforce (equation 5).

$\begin{matrix}{F_{SW} = {{c_{w} \cdot A_{S}}2\frac{\rho_{F} \cdot w_{F^{2}}}{2}}} & {{Equation}\mspace{14mu} 3} \\{F_{S} = {g \cdot \rho_{S} \cdot V_{S}}} & {{Equation}\mspace{14mu} 4} \\{F_{A} = {g \cdot \rho_{F} \cdot V_{S}}} & {{Equation}\mspace{14mu} 5}\end{matrix}$

where

F_(SW)—flow force

c_(w)—flow coefficient of drag of a dust grain

w—flow rate of the fluid

F_(S)—weight force of the dust grain

A_(s), V_(s)—surface, volume of the dust grain

p_(F),p_(S)—density of the fluid, of the dust grain

G—acceleration due to gravity

In both cases, the weight forces are of equal magnitude and will not beconsidered any further. The lift force is negligibly small, because thedensity difference between flue gas and dust grain is very great. Thismeans that only the flow force need be compared.

$\begin{matrix}{{c_{w} \cdot A_{S} \cdot \frac{\rho_{F \cdot {air}} \cdot w_{air}^{2}}{2}} = {c_{w} \cdot A_{S} \cdot \frac{\rho_{F \cdot {Oxy}} \cdot w_{Oxy}^{2}}{2}}} & {{Equation}\mspace{14mu} 6}\end{matrix}$

Equation 2 for the impulse flow maintenance is therefore applicable andthis ensures that the coal is removed.

The oxygen content of the burner gas flows 38 or of the burner “airs” isset such that the adiabatic combustion temperature remains virtuallyconstant.

Since the stoichiometry in the burner area in modern power stations isrestricted on the one hand at the top by the formation of NOx which isthen increased and on the other hand at the bottom by the risk of theformation of skeins of reducing atmosphere in the combustion area 18,resulting in the possibility of increased wall corrosion, the designvalue for the combustion stoichiometry must also be complied withapproximately in the oxyfuel case. Since the risk of the formation ofthermal nitrogen oxide is reduced by the lack of nitrogen from the air,slightly increased stoichiometries may also be used, however, to set thelevel of the combustion area temperatures.

Furthermore the oxygen contents of the transport gas and of the othergas flows should differ by up to 15% by mass depending on the fuelcharacteristics, in particular the capability to ignite the coal. Thisallows the over fire speed in the flame to be controlled in order toallow the temperature profiles in the combustion chamber 25 of the steamgenerator 11 to be similar to those of the air combustion.

Finally, the temperature profile and temperature level are responsiblefor the heat transfer, which dominates in the combustion area 18 of thesteam generator 11, by radiation in this area, which is the governingdesign criterion in order to comply with the required combustion chamberfinal temperature and the amount of heat transferred to the water, asthe working medium, in the combustion chamber walls.

FIG. 2 does not illustrate the so-called curtain or side-gas injectionwhich is used in some power stations in order to reduce the risk ofreducing areas in the vicinity of the combustion chamber walls, and toavoid the risk of increased wall corrosion. In the exemplary embodiment,its proportion in the total amount of gas or “air” supplied in the areaof the burner 10 remains low without any change, in order to stillprovide the impulse flow which is necessary for the penetration depthand coverage of the entire wall. However, its oxygen content in theoxyfuel mode is increased by up to 20 percentage points in comparison tothe pure air mode, in order to provide effective protection against thehigher CO contents (in this part of the combustion area) occur becauseof the Boudouard equilibrium and the high CO₂ contents.

The proportion of the recirculated flue gas which is added in the upperpart of the combustion chamber 25 of the steam generator 11 as over fireair (OFA) 37 is governed by the fixing of the other gas flows. Theoxygen content in the over fire air (OFA) is determined from the overallstoichiometry, that is to say from the excess oxygen which is requiredoverall for reliable combustion of all the coal components and so as tominimize the CO content—the stoichiometry factor in the exemplaryembodiment is 1.17. Depending on the design basis of the power station,however, it can assume values between 1.1 and 1.25 for the air mode, butshould be as low as possible in the oxyfuel case in order to avoidfurther dilution of the CO₂ by excess oxygen.

This essentially precludes the transfer of the process parameters fromthe air mode to the oxyfuel mode. In addition to the described analogyof the flow impulses, a further heat-engineering optimization of thecombustion for the oxyfuel mode can be implemented by including detailedCFD (computational fluid dynamics) results and experimental results forspecific coals, although these have only a minor influence on theamplitude of the process parameters set. In all cases—that is to sayeven if the recirculation gas flows are split differently and the oxygencontents vary—the described procedure and consideration of the availabledegrees of freedom for the oxyfuel mode allow both the conventional airmode and an oxyfuel mode to be carried out in a power stationinstallation modified in this way. It is thereby possible in the oxyfuelmode for essentially the same steam parameters to be set in the steamgenerator 11.

The purging and/or barrier gas (air) which is used nowadays in/onrotating parts of the coal mills 36 associated with the power station isreplaced by CO₂ during the conversion to the oxyfuel mode.

As FIG. 2 shows, the air preheater 8 is still required in theillustrated exemplary embodiment. The recirculated amount of flue gasfed back cannot, however, absorb the total amount of heat that isrequired, because oxygen is still lacking, since the oxygen is not mixedwith the flue gas before the air preheater 8. However, this is alsoundesirable since conventional regenerative air preheaters in the designcase for air operation have unavoidable leakage in the direction of theflue gas between the two gas flows (off-gas and recirculated flue gas)which flow in opposite directions. Oxygen losses (and a greater energyconsumption) as well as reduced CO₂ purity would therefore be expectedin the oxyfuel mode. For this reason, a gas/gas heat exchanger 19 inorder to preheat the oxygen, is installed together with a control valveto split the flue gas to be cooled down, in the bypass to the airpreheater 8 for the oxyfuel mode. In the pure air mode, the oldoperating state can therefore still be selected by disconnecting theoxygen preheater by closing the bypass by closing the control valve.

Depending on the type of air preheater 8 (that is to say with a rotatingstored mass or with rotating shrouds), the sealing from the environmentcan be improved with greater or lesser complexity since there is stillthe reduced pressure at this point on the flue-gas side.

In order to prevent more environmental air from entering the steamgenerator 11 in the area of the funnel 41 of the steam generator 11, itis in any case advantageous during the conversion process for the steamgenerator 11 to be equipped for wet ash removal if dry ash removal isinstalled in the existing installation. In the case of wet ash removal,adequate sealing is ensured in any case by the sealing of thewater-filled trough with respect to the steam generator walls.

No significant changes need be made in the area of the electrical filter13. However, care should be taken to ensure that the shut-off devices tothe ash removal system of the electrical filter 13 are designed to begas-tight (for example gas-tight bucket feed gates). To entirely preventthis leakage flow of leakage air in the system CO₂ should be applied tothe shut-off devices as a sealing barrier gas.

In this way, no significant structural change need be made in thedenitrification installation (SCR=selective catalytic reduction) 12.Mixed gas flows for which air is used in normal operation are replacedin the oxyfuel mode by CO₂ (see the arrow in FIG. 2) which can be afteror in an intermediate stage of compression. In principle, both ammoniaand ammonia water can still be used as reactants.

Since the chemical reactions within the flue gas desulfurizationinstallation (REA) 15 take place in an atmosphere composed mainly of CO₂in the oxyfuel mode, the absorbent should be changed from limestone(CaCO3) to quicklime (CaO) since the CO₂ release which is required todissolve the limestone in the dissolving process is impeded by thesaturation of the wash suspension with CO₂. The absorbent mixing systemsmust be appropriately modified for this. Next, when flue gasdesulfurization is carried out using the methods that are normally usednowadays, the calcium sulfide which is created in the solution isoxidized by air injection to form calcium sulfate, this method step isalso modified during the conversion/modification to the oxyfuel mode.Since, for cost reasons, the oxidation in an installation designed forthe air mode is carried out by injecting air into the sump of a spraytower, desired oxygen would once again not be introduced when using airwithout a hardware change. Pure oxygen must not be injected since, onthe one hand, the production of this oxygen would result in acorrespondingly greater energy requirement for the air separation unit(ASU) 20. On the other hand, the need for excess oxygen leads to the CO₂provided for storage being of lower purity. For this reason, in theexemplary embodiment, the desulfurization is converted to externaloxidation by fitting an external stirring container 39 (FIG. 3), thuspreventing N₂ and O₂ from being introduced into the system.

Since the desulfurization installations now being designed for the lawsapplicable in Germany achieve an SO₂ value of <200 mg/Nm³ (dry, with thecurrent oxygen content), the desulfurization must be improved in orderto prevent corrosion problems in downstream process steps (compression,transport to the storage location). Furthermore the fresh-air fan 7 andthe fuel/air channels are also not designed for increased SO₂/SO₃contents on conversion/modification to oxyfuel operation. An increase inseparation can be achieved in two ways. On the one hand, the existingDeSOx can be improved within limits by increasing the ratio of liquidcirculation to flue gas flow, while on the other hand a further spraylevel can be retrofitted if sufficient space is available in the headarea of the spray tower. Retrofitting a tray or the addition of acidswhich promote solution likewise improves the desulfurization.

This allows high desulfurization levels to be achieved and SO₂/SO₃values of 20-40 200 mg/Nm³ (dry, with the current oxygen content).Further purification is carried out before compression and after theflue gas recirculation in order to ensure that only the required fluegas flow need be purified to the pure gas values required bycompression.

In order to dry the flue gasses after the flue gas desulfurizationinstallation (REA) process, the flue gas desulfurization installation(REA) 15 is followed by a flue gas condensation drier 21. This cools theflue gases further in order to achieve the required water contents of<3% (for recirculation).

In addition to the cooling water that is required—if present asproduct—the liquid nitrogen from the air separation unit 20 is also usedfor this purpose. After drying, the flue gas flow is split, and themajority is recirculated 22, 23. The flow element which is intended tobe supplied to the compressor 24 is pased on for further purification.

Before the CO₂ compressor station 24, corrosive elements of the fluegases and water should be removed as far as possible. An NaOH washerwith recirculation flow cooling is used for this purpose. During NaOHwashing, a further considerable reduction in the corrosive flue gascomponents is achieved (SO₂/SO₃<<5 mg, HCl<<1 mg, HF 1 mg, dust<<1 mg),the cooling of the circulating liquid ensures that the water content isreduced further. A further, downstream condensation cooler is optionallyused.

The flue gases which have been purified in this way are supplied to thecompressor station 24. After compression, the residues of O₂ and N₂which are still present in the gas flow are removed from the liquefiedCO₂ by a phase separator, since these gases are not liquefied in theseconditions. The CO₂ is now available for storage and further transport.

The processes of more extensive flue gas purification described aboverequire high cooling powers. Liquid nitrogen produced in the airseparation unit (ASU) 20 can be used in conjunction with a cooling waterflow for this purpose (if oxygen and nitrogen as the products of the airseparation are in liquid form). The nitrogen is first of all used in thecooling system of the multistage CO₂ compressor 24, in order to minimizethe energy consumption of the compressor. The energy transferred to the“superheated” nitrogen is then optionally partially recovered by meansof an expansion turbine, in which process the nitrogen temperature fallsagain. Furthermore, the mass flow of nitrogen is then used via couplingheat exchangers both for cooling the NaOH recirculation and for coolingthe flue gas condensation drier 21 arranged downstream from the flue gasdesulfurization installation (REA) 15, where cooling water flows areadded to it. The nitrogen can then optionally once again be passed viaexpansion turbines for energy recovery, and fed back into theenvironment via a stack.

The described procedure for designing the combustion process of anoxyfuel steam generator can also be iteratively coupled to the normaldesign of the convective heating surfaces of a steam generator and canbe used for cost-optimized design of a new installation by reducing thesize of the heating surfaces while at the same time increasing the fluegas speed by reducing the cross section of the combustion chamber. Fromthe flow mechanics point of view, it is now necessary to depart from adirect analogy with the impulse relationships: the case of aircombustion can then be designed (for the same flow speed which islimiting under erosion viewpoints) with a correspondingly reduced power(partial load for starting/shut-down processes and operatingdisturbances).

The following explanations likewise relate to a conversion concept for acoal-fired power station. The options for implementation of a CO₂-freepower station in which the CO₂ is separated and stored is discussed, andwhat the advantages and disadvantages are. The state of researchrelating to the oxyfuel process is described briefly. After a discussionof possible variants of the oxyfuel process, two variants are selected.These are analyzed in terms of the conversion measures required to thepower station components: combustion gas system, flue gas cleaninginstallation, mills, burners and steam generators. Heat engineeringcalculations relating to heat transfer in the steam generator indicatethat the required steam parameters are achieved without conversion ofthe steam generator heating surfaces. Subsequent calculations, with therecirculation mass flow and the radiation change coefficients of thecombustion chambers being varied indicate ways to influence the heattransfer in the steam generator. Assessments of the conversion effortfor the two selected process variants and a final estimate of theoverall efficiency indicate which considered variant is technically andeconomically the most advantageous.

The aim of the oxyfuel process is to achieve as high a CO₂ concentrationas possible in the flue gas in order to save the energy-consuming CO₂washing of the “post combustion process”. During the compression of theCO₂, the energy consumption can be reduced if the CO₂ has a highconcentration. The compressor power is then applied only to the CO₂ andnot to the impurities as well. During combustion with air, the nitrogencomponent of approximately 78% by volume prevents high CO₂ enrichment inthe flue gas. If, in contrast, to this, pure oxygen is used forcombustion, considerably higher CO₂ contents of up to 80% by volume canbe achieved during combustion using dry brown coal, and more than 90% byvolume when using hard coal. These values may fluctuate depending on thecombustion conditions and the coal composition. Nevertheless, they aregood preconditions for separation and storage of CO₂.

When burning coal with pure oxygen in the oxyfuel mode, there is nonitrogen, which on the one hand acts as heat carrier for flametemperatures that can be coped with technically and on the other handensures that the flue gas volume flow is increased. This flue gas volumeflow removes the required heat flow into the convective part of thesteam generator where it also ensures the high flow speeds required forheat transfer. In order to provide this volume flow, the flue gas is atleast partially recirculated after combustion in the oxyfuel mode and,after being mixed with oxygen, is once again supplied to the steamgenerator 11. The flue gas can be removed at various points downstreamfrom the steam generator 11. The choice of the recirculation location 1to 6 results in different concentrations of dust, SO_(x) and water inthe flue gas.

The heat transfer in the steam generator 11 takes place by convection orby radiation. For convective heat transfer, a changed flue gascomposition results in changed values of heat capacity, viscosity andthermal conductivity as well as flue gas density, as shown in FIG. 8.The flow speed of the flue gas is therefore also changed. However, it ispossible to achieve similar heat flows in the convective heatingsurfaces as well with oxyfuel flue gas in the oxyfuel mode. The initialsupposition that larger heating surfaces would be required in oxyfuelconditions, in order to transfer the heat flows, proves incorrect. Browncoal with a combustion heat of 22 MJ/kg (net) and a moisture content of19.95% is thus burnt, and the flue gas is dried before recirculation.With the same flue gas mass flow and a combustion area outlettemperature that is higher by 46 K, a flue gas temperature that isreduced by 4 K in comparison to the air process is measured at theoutlet of the economizer heating area. A higher heat flow is thereforetransferred in the convective part. When using the oxyfuel process inalready existing installations or installations that are being built,and which are designed for air operation, there is therefore no need forany relatively major modifications to the convective heating surfaces.

The heat transfer ratios can therefore be matched by adaptation of themolar recirculation ratio.

Molar recirculation ratios of 3.25 are determined for the moist feedbackof the flue gas (removed at location 5) and 2.6 for feedback at location6 after the flue gas drying 21. As the recirculation ratio rises, theheat transfer by radiation decreases, because the flame temperatures arelower.

The radiation heat transfer varies in particular as a function of thecomposition and the temperature of the gas. There are various possibleways to adjust the flame and flue gas temperatures as well as the gascompositions. The most important ways include the oxygen content in thecombustion gas and the proportion of the recirculated gas mass flow inthe flue gas mass flow that is produced overall.

The following flue gas constituents principally influence the gasradiation behavior:

-   -   CO₂ content    -   H₂O content    -   Proportion of solid particles.

The high proportion of nitrogen in the flue gas in the case of aircombustion is replaced by CO₂ in the oxyfuel process. Depending on therecirculation location 1 to 6, the flue gas contains a greater or lesseramount of water. However, CO₂ and H₂O are not diathermic in the same wayas N₂ and O₂, but themselves absorb and emit heat radiation depending onthe gas temperature. In addition, the higher heat capacity of thecombustion gas, primarily caused by CO₂ and water, changes importantflame characteristics.

Emissitivity of the flame in the oxyfuel mode and in the air mode issimilar. It depends in particular on the coal, the fly ash, sootparticles in the flame, but not on the CO₂ concentration.

In comparison with air operation, for the same oxygen content in thecombustion gas, it is generally observed in the oxyfuel process that

-   -   the flame propagation speed falls,    -   the flame temperatures fall, and    -   the ignition delay increases.

The ignition delay is calculated by dividing the movement distance overwhich the coal particles travel before ignition by the particle speed.

The ignition delay rises when

-   -   the temperature falls,    -   the oxygen content in the combustion gas falls,    -   the heat capacity of the combustion gas rises,    -   the thermal conductivity of the combustion gas falls, and    -   the proportion of volatile components in the coal falls.

In this case, each of the other parameters remained constant.

In a CO₂-rich atmosphere, the ignition delay is greater than in anitrogen-rich atmosphere (air operation), given the same oxygen content.In order to achieve the same ignition delay as with air combustion, thegas must consist of 30% by volume of oxygen and 70% by volume of CO₂ inthe oxyfuel gas.

The influence of the motor recirculation ratio is also evident here.Given a recirculation R

$R = \frac{{\overset{.}{m}}_{Reci}}{{{\overset{.}{m}}_{Reci} + \overset{.}{m}},_{{off}\text{-}{gas}}}$

of 0.58, in addition to the adiabatic combustion temperature, which isthe same as that for the air mode, similar flame temperature profilesand stabilities are also observed in the oxyfuel mode (R=recirculationratio, m_(Reci)=mass flow of recirculated flue gas, m_(off-gas)=massflow of off gas).

As FIG. 4 shows, various heating surfaces, which differ in terms of theheat transfer method, exist in a steam generator 11. Heat transfer byradiation is dominant in the combustion chamber 25 and in the radiationareas 26 and 27, and these are therefore referred to as radiationheating surfaces. The combustion chamber 25, the radiation areas 26 and27 are together referred to as the combustion area 18. The heat transferin superheater heating surfaces 28 and 29 and intermediate superheaterheating surfaces 30 and 31 as well as the economizer heating surface 32takes place mainly by convection, as a result of which these heatingsurfaces are referred to as convective heating surfaces. The convectivepart of the steam generator 11 represents the totality of all convectiveheating surfaces.

The supporting tube bulkhead 49 has the special feature of also having alarge radiation component as a convective heating surface. This can beexplained by its position as the first bundle heating surface above thecombustion area 18.

The final stages of the HP (high-pressure) and MP (medium-pressure)parts and of the economizer heating surface have flow passing throughthem in the sense of a parallel-flow device. In the final stages, thisis used to reduce the corrosion tendency by means of lower materialtemperatures, and to protect the turbine against temperaturefluctuations. The economizer heating surface 32 is intended to guaranteethat any steam bubbles that may occur are removed.

The aim is to convert a 600° C. or 700° C. power station designed forair operation to the oxyfuel process. This means that the steamgenerator 11 must be able to supply the turbine with the required steamparameters in both the air mode and the oxyfuel mode. The aim is to dothis without any modifications to the steam generator heating surfaces,mills and burners.

The critical criterion for the economy of the oxyfuel process is toachieve a high CO₂ content in the off-gas. Only considerable energysavings in the CO₂ concentration and compression justify the high-energyoxygen generation as an additional process in comparison to simple fluegas washing with a washing agent (for example monoethylamine). Any airleakages which enter in addition to the purging air and barrier air thatis supplied counteract this aim, and must therefore be reduced to aminimum.

As FIG. 1 shows, it is possible to tap off flue gas for flue gascirculation at the following points:

-   -   1, before the denitrification 12,    -   2, after the denitrification 12,    -   3, after the regenerative air preheater 8,    -   4, after the dust removal 13,    -   5, after the desulfurization 15 or    -   6, after the drying 21.

It is also possible to combine a plurality of these tapping options.

The recirculation of the flue gas at the point 1 before thedesulfurization installation 12, which is arranged in the empty draft inmodern coal-fired power stations, results in enrichment of the flue gaswith dust, sulfur oxides and water. All lines and components which comeinto contact with flue gas must be designed to be appropriatelydust-compatible. This applies in particular to the recirculation fan 48,48 a, 48 b which has to be additionally installed. The higherconcentration of water and sulfur oxides results in the sulfuric aciddew point rising.

Neither existing regenerative air preheaters 8 nor a heat displacementsystem 16 before the flue gas desulfurization installation 14, 15 arerequired in the oxyfuel mode since, when a large proportion of the fluegas is tapped off before the air preheater 8, there is no substance flowto be cooled down or heated. An existing electrical filter 13 and theflue gas desulfurization installation 15 are then overdesigned for theoxyfuel mode. The flow ratios can be adapted, if necessary, for optimumdust separation and desulfurization rate by shutting down individualelectrical filter passages or washer levels. The drier 21 which isprovided only for the oxyfuel mode can in this case be designed forsmall volume flows. The oxygen flow is then heated in an additional heatexchanger 33, which is arranged before the electrical filter 13, wherethe flue gas temperature is about 380° C.

When the flue gas is recirculated from the point 2, only the conversionrate from SO₂ to SO₂ is increased in comparison to this, since the fluegas passes through the area of the catalytic surfaces of thedenitrification installation 12, resulting in a higher sulfuric aciddew-point temperature.

When flue gas is tapped off at the recirculation point 3, only the airpreheater (LUVO) 8 is then used to cool down the flue gas. The flue gastemperature behind the air preheater (LUVO) 8 is then above the sulfuricacid dew point. The temperature of the flue gas after the air preheater(LUVO) 8 is regulated by the inlet temperature of the medium to beheated and is passed through in the opposite direction. However, thisresults in the problem that, because the recirculated flue gas is heatedup in the recirculation fan, the mass flow to be heated on re-enteringthe air preheater is hotter than the mass flow to be cooled down at theoutlet. This problem can be solved by fitting a heat sink in the form ofa heat exchanger. The discrepancy between the flue gas mass flow on theside of the air preheater (LUVO) to be cooled down and on the side to beheated up is solved by an air preheater (LUVO) bypass 34 with oxygenpreheating 33.

When the flue gas is recirculated from the point 4, behind theelectrical filter 13, the flue gas is enriched with sulfur oxides andwater. The dust load for flue gas channels and fans decreasesconsiderably. The electrical filter 13 is then designed and constructedsuch that it can be used both for the air mode and for the oxyfuel mode.

When the flue gas is recirculated from the point 5, after thedesulfurization 14, 15, the flue gas is now further enriched only withwater since large amounts of the sulfur are removed in the flue gasdesulfurization installation 14, 15. This reduces the risk of corrosioncaused by sulfuric acid. The quench effect in the flue gasdesulfurization installation 15 cools the flue gas by partialvaporization of the absorber suspension. In this case, the water contentand the outlet temperature of the flue gas are set as a function of thesaturation temperature.

When the flue gas is recirculated from the point 6, behind the drier 21,the flue gas is sucked back or fed back (recirculated) with all the dustremoved, after desulfurization and dried. With this flue gas quality,the fresh-air fan can be used as recirculation fan. All the heatexchangers and flue gas treatment components used in the air mode can beoperated in the oxyfuel mode without any change from the air mode.However, the entire flue gas mass flow is passed via the drier 21 whichmeans that this must be designed to be appropriately large in order tobe able to carry away large heat flows.

The advantages and disadvantages of the respective recirculation pointscan be combined by recirculation of specific flue gas flow elements atvarious ones of the points 1-6.

A flow element which has been passed through all the flue gas treatmentcomponents is correspondingly purified, as a result of which theconcentrations of hazardous substances such as dust, water and sulfuroxides are reduced. A second flow element can then be recirculated veryclose to the steam generator 11, for example at the point 1, at a highenergy level. There is therefore no need for this flue gas flow elementto be cooled down and heated up again later.

In the case of later recirculation, that is to say when the overall fluegas mass flow flows through an increasing number of components for fluegas treatment along the flue gas path after emerging from the economizerheating surface, this results, rising from the points 1 to 6, inincreasingly

-   -   less enrichment of the flue gas with water, dust and sulfur        oxides,    -   better usefulness of the original components and parts of this        section of the coal-fired power station in the air and oxyfuel        modes, and    -   less need to introduce or to install diverse additional        components and/or installation parts.

Conversion or modification to the oxyfuel process changes therecirculation mass flow which, together with the mixed-in oxygen massflow and with the flue gas temperature profile unchanged, primarilyinfluences the flow speeds in and on the heating surfaces. The higherdensity of CO₂ (oxyfuel mode) in comparison to N₂ (air mode) results ina slower flow for the same mass flow. The flow speed of the flue gasplays an important role, in addition to physical characteristics such asviscosity, thermal conductivity and heat capacity, in the heat transferfrom the flue gas to the heating surface. The required steam parametersare achieved, despite the changes in the heat transfer conditions. Inthe case of steam generators based on the Benson principle, the controlsystem introduces as much fuel as is required, and for as long as isrequired, to reach the high-pressure (HP) outlet mass flow, and thetemperature is controlled by enthalpy control and injection. Themedium-pressure (MP) outlet temperature can be influenced by themagnitude, that is to say the amount, of the recirculation mass flowwhich ensures advantageous flow speeds for heat transfer. The excessoxygen λ₀₂ means the ratio of the oxygen flow m₀₂ supplied to thestoichiometrically required oxygen flow m_(O2,min). For air combustion,the combustion air mass flow m_(air) required for this is calculatedusing the equation

${\overset{.}{m}}_{air} = {{\overset{.}{m}}_{{O\; 2},\min} \cdot \frac{100}{21} \cdot {\lambda_{O\; 2}.}}$

The excess air then corresponds to the excess oxygen.

There is no point in using excess air or producing a relationship withthe burner gas in the oxyfuel process. It is possible to achievevirtually any desired oxygen contents in the burner gas and flue gas.The original term excess oxygen, which relates to the fuel mass flow, istherefore reverted to. This is calculated in the case of oxyfuelcombustion using

$\lambda_{O\; 2} = \frac{{{\overset{.}{m}}_{ASU} \cdot x_{{O\; 2},{ASU}}} + {{\overset{.}{m}}_{leak} \cdot x_{{O\; 2},{leak}}} + {{\overset{.}{m}}_{Reci} \cdot x_{{O\; 2},{Reci}}}}{{\overset{.}{m}}_{{O\; 2},\min}}$

where

-   -   m_(LZA)—mass flow from the air separation unit    -   x_(02,LZA)—oxygen content after the air separation unit    -   m_(leak)—leakage air mass flow    -   x_(02,leak)—oxygen content of leakage air    -   m_(Reci)-recirculation mass flow    -   x_(02,Reci)—oxygen content of the recirculated flue gas    -   m_(02,min)—stoichiometric oxygen flow.

In this case, the numerator contains all the oxygen mass flows(combustion gas, feed gas, process gas) supplied for combustion. Thedenominator contains the stoichiometric oxygen requirement, which iscalculated from the reaction of the coal components C, H, O and S toform CO₂, H₂O and SO₂.

A comparison of the flue gas compositions that occur between the airmode and the oxyfuel mode with flow gas circulation after the electricalfilter 13 at the point 4 and after the drier 21 at the point 6 is shownin FIG. 9.

The change in the gas composition also results in different physicalcharacteristics. FIG. 10 shows the higher density of the flue gas in theoxyfuel process (+23.9%+33.3%). The heat capacity, dynamic viscosity andthermal conductivity of the flue gases vary only slightly in comparisonto the air mode when the flue gas is taken off at the point 6. In theoxyfuel process, the higher heat capacity and the higher thermalconductivity at the point 4 in comparison to the point 6 can beexplained by the water content of the flue gas being even higher there.

In order to achieve the steam parameters before the turbine in theoxyfuel process as well, the fuel mass flow and the recirculation massflow are adapted. Because of the higher density of the flue gas in theoxyfuel process, the flow in the convective part is slowed down, despitethe flue gas mass flow being higher.

The physical characteristics from FIG. 10 are included in the Reynoldsnumber and Prandtl number, which in turn lead to the Nusselt number.

$\alpha_{{outer} \cdot {convective}} = \frac{\lambda_{FG} \cdot {Nu}}{l}$α_(outer) = α_(outer ⋅ convective) + α_(outer ⋅ radiation)$\frac{1}{k} = {\frac{1}{\alpha_{outer}} + {\sum\limits_{n = 1}^{N}\frac{\delta_{n}}{\lambda_{n}}} + \frac{1}{\alpha_{inner}}}$$\overset{.}{Q} = {{k \cdot A \cdot \Delta}\; T_{m}}$

where

-   -   l—characteristic dimension (for example pipe diameter)    -   Nu—Nusselt number    -   δ_(n)—layer thickness    -   λ_(n)—coefficient of thermal conductivity of the layer (for        example pipe)    -   A—heat exchanger area

The improved heat transfer by radiation in the area of the convectiveheating surfaces by more than 39% is significant. In the case of theoxyfuel process with recirculation at the points 4 and 6, this isbecause of the high CO₂ concentration, and at the point 4, it is becauseof the increased water concentration. The heat transfer coefficient k isincreased by the greater proportion of the radiation in the heattransfer in the convective part.

Overall, as can be seen from FIG. 10, the heat flow transferred in theconvective part is increased. However, the heat transfer in theconvective part also depends on the heat transfer in the radiationheating surfaces. This is because of the conditional flue gas andwater/steam temperatures. The radiation heating surfaces are locatedbefore the convective heating surfaces 28 to 32, 49 along the flue gaspath in the combustion chamber 25 and the radiation areas 26, 27. Withthe economizer heating surface 32, the water first of all flows througha convective heating surface, followed by the radiation heating surfacesfor vaporization, and finally once again convective heating surfaces forsuperheating the steam.

If the total heat flow transferred in the steam generator 11 is thesame, the flue gas will be considerably cooler because of the higherheat capacity in the oxyfuel process in the combustion chamber 25 and,at the end before the air precooler, will be somewhat hotter than in thecase of the air process. It is therefore not absolutely essential toreach the adiabatic combustion temperature of the air process.

A change in the warming-up ranges in the superheaters and intermediatesuperheater heating surfaces should be observed. In all convectivehigh-pressure heating surfaces, the warming-up ranges are higher than inthe air process in the oxyfuel process using the circulation points 4and 6. In contrast, only the heating surface 39 reaches a greaterwarming-up range in the medium-pressure heating surfaces.

The most important conversion for the oxyfuel mode is to feed back aportion of the flue gases. The recirculation gases are tapped off andfed back after the suction draft 17. FIGS. 2 and 11 illustrate the feedback, with FIG. 11 additionally showing the temperature and mass flowdetails of the fed-back flue gas flow, of the oxygen supplied from theoxygen preheater, as well as thermal energy flows. The components to beconverted or to be added in comparison to an air mode are shown on agrey background. The required pressure increase in order to overcome theflow resistances and in order to produce a pressure gradient in the airpreheater 8 and in the gas channels is produced by a recirculation fan48, 48 a, 48 b.

After heating the flue gas by means of the suction draft 17 and then bymeans of one of the recirculation fans 48, 48 a, 48 b, the temperatureon the recirculation side is higher in the flow direction before the airpreheater (LUVO) 8 than on the flue gas side in the flow directionbehind the air preheater (LUVO) 8. The flue gas can therefore not becooled down to a lower temperature, without any further measures, in theair preheater (LUVO) 8 before entering the electrical filter 13. Thecooling down in the air preheater (LUVO) 8 on the flue gas side istherefore controlled via the heat exchanger 35 (WÜ3), 16 by setting atemperature on the recirculation side before the air preheater (LUVO) 8.Furthermore, the heat transfer in the air preheater (LUVO) 8 is governedby the mass flows. In order to achieve the same flue gas temperatures atthe inlet to the flue gas desulfurization installation (REA) 15 as inthe air process, the flue gas is cooled down further after the suctiondraft 17.

The flue gas desulfurization installation 15 designed for the air modeis normally overdesigned for the oxyfuel mode, and adaptation to thereduced volume flow and the higher sulfur concentration may benecessary. This can be done by a design in which a relatively largeportion of the washer can be shut down in the oxyfuel mode. Appropriaterequired flow speeds are then set in the smaller part that is used. Theentire flue gas desulfurization installation (REA) 15 would be used inthe air mode. The air supplied in the air process in order to improvethe reaction must be replaced in the oxyfuel mode by external oxygeninjection (external oxidation) 39, in order not to reduce the CO₂concentration in the flue gas. These two heat exchangers are used forfeed water preheating. The flow speed in the oxyfuel mode is reduced incomparison to the air mode because of the increased density of the fluegas. In addition, the heat transfer on the flue gas side is changedbecause the physical characteristics are different. A reduced heat flowis transferred. In order to change the intermediate temperatures of thefeed water preheating as little as possible, the mill circulating flowcan be increased by about 60%. This then results in negative feedbacksto the bleeds on the turbine, and in a positive increase in theheat-absorbing mass flow in the air preheater (LUVO).

The hot-gas temperature required for coal drying can be determined. Coldair is admixed before the mill in the air process, in order to controlthis temperature. Instead of this, recirculated flue gas containing CO₂is used for a high CO₂ concentration in the off gas in the oxyfuelprocess. Correspondingly cold flue gas is tapped off behind the flue gasdrier and condenser 21 at about 25° C. After increasing the pressure andheating, it is mixed in the required proportion before the mills 36 at30° C., by means of an additional fan.

The flue gas can absorb the fuel moisture and the conventional siftertemperature in the mills 36 of 90° C. need not be increased forsaturation reasons. The dew-point temperature of the sulfuric acid isundershot in the mills 36 and likewise in the oxygen preheater, in theheat exchangers and in the mill circuit fan, as well as thecorresponding associated gas channels. As a countermeasure, the surfacesof these components may be coated with plastic, if required. However,this additional layer has the disadvantages that it impedes heattransport and offers scarcely any resistance against erosion.

The flue gas recirculation mass flow has an important influence on theflow speed of the flue gases in the convective part of the steamgenerator and on the adiabatic combustion temperature. A reduction inthe flue gas mass flow at the burner acts like an increase in the oxygencontent on the processes in the combustion chamber 25 and in thecombustion area 18.

Overall, the increase in the recirculation mass flow results in aslightly greater heat flow being transferred in the convective heatingsurfaces, and a reduced heat flow being transferred in the radiationheating surfaces.

FIGS. 1, 2 and 11 show the process layouts in a flue gas circulation atthe point 6. The flue gases are tapped off behind the flue gas drier 21,and are fed back. Since the flue gas is cooled down to 25° C. in thedrier 21 and a major level of dust removal and desulfurization arecarried out, the fresh-air fan 7 can also be used as a recirculationfan.

Behind the fresh-air fan, the recirculated flue gas is heated in theheat displacement system (WÜ3) 35 to 107° C. This temperature has aninfluence on the cooling down of the flue gas in the air preheater 8,which should be done at most to above the sulfuric acid dew point. Theheat displacement system (WÜ3) 35 is no longer in the form of aregenerative heat exchanger in the oxyfuel mode, because this does notallow the desired media temperatures to be achieved. The heat transferin the air preheater (LUVO) 8 is controlled by the distribution of theflue gas mass flow between the air preheater (LUVO) 8 and the airpreheater (LUVO) bypass 34.

The inlet temperature into the flue gas desulfurization installation(REA) 14, 15 is predetermined by the heat flow which can be transferredto the recirculated flue gas in the heat displacement system (WÜ3) 35,16, without any negative influence on the cooling down of the flue gasin the air preheater (LUVO) 8. The flue gas in the flue gasdesulfurization installation (REA) 14, 15 is 12% warmer than in the airprocess.

The processes in the steam generator will be considered in order toexamine possible ways to influence the heat transfer in the steamgenerator in the oxyfuel mode. Constant preheating of the combustiongases is assumed. The injections in the HP and MP parts of the steamgenerator are kept constant. The results are determined with the optimumoperating point of the fuel, oxygen and recirculation mass flows inorder to achieve the steam parameters before the turbine.

In the oxyfuel mode, the adiabatic combustion temperature rises becausea reduced flue gas mass flow has to be heated at the burner. Thisresults in a greater heat flow being absorbed in the vaporizer. Thereduced flue gas mass flow is cooled down more quickly in the convectivepart, as a result of which the flue gas after the intermediatesuperheater heating surfaces 31 is cooler than in the air mode. Thesteam outlet temperature in the HP part is 17 K higher than in the airmode. This is probably because of the increased heat absorption in thevaporizer. The MP part of the steam generator 11, consisting of pureheating surfaces, in contrast does not reach the required warming-uprange, as a result of which the temperature before the turbine is 17 Klower than in the air mode.

While the heat absorption in the convective heating surfaces in thesteam generator 11 falls, it rises in the radiation heating surfaces.

If the recirculated mass flow is reduced by 20% and the conditions ofimpulse maintenance and oxygen content in the carrier gas aremaintained, then the recirculated gas mass flow is furthermore notsufficient for impulse maintenance in the secondary gas. Less flue gasis then passed via the secondary gas, and no more is passed via theupper gas nozzles into the steam generator.

The fuel mass flow is now set such that the required HP outlet mass flowis achieved. This is linked with adapting the oxygen mass flow in orderto maintain the desired excess oxygen of 1.17. The water mass flowinjected for cooling before the intermediate superheater heatingsurfaces 31 is used to control the MP outlet temperature. This reducesthe fuel mass flow by 2.5% in comparison to the optimum state in the airmode. In consequence, the adiabatic combustion temperature rises lessseverely and a somewhat reduced heat flow is absorbed by the radiationheating surfaces. The flue gas cools down more quickly due to thereduced heat flow introduced, and is already cooler behind thesuperheater heating surfaces 29 than in the optimum case in the airmode. Together with the reduced flue gas mass flow, this affects theheat transfer in the MP part. Despite reducing the injected cooling massflow by 100%, the required outlet temperature on the intermediatesuperheater heating surfaces 31 cannot be achieved.

If, in contrast, the recirculated flue gas mass flow is increased by 20%and the conditions for impulse maintenance and oxygen content in thecarrier gas and secondary gas are maintained, and if, furthermore, theupper gas nozzles pass excess sucked-back flue gas into the steamgenerator, the required HP outlet mass flow can be achieved byadaptation of the fuel mass flow. The excess oxygen of 1.17 should inthis case be retained. The water mass flow injected for cooling beforethe intermediate superheater heating surfaces 31 is used to control theMP outlet temperature.

In this case, the steam generator control reacts to the steamtemperature not being achieved at the outlet of the HP part byincreasing the fuel mass flow by 2.5%. This results in the adiabaticcombustion temperature rising and thus also the heat absorbed in thecombustion chamber and the bulkhead heating surface. The somewhatgreater volume flow as a result of the increased flue gas temperaturesfuels better heat transfer in the convective part of the steamgenerator. The MP part is affected negatively by this. The warming-upranges of the heating surfaces before the water injection are enlarged,which can be compensated for by quadrupling the injected water massflow.

If the radiation exchange coefficient in the combustion chamber 18 isreduced by 30% from 1.636 to 1.145 and the fuel, oxygen andrecirculation mass flows are kept constant, the reduction in theradiation exchange coefficient also causes the heat absorbed in thecombustion chamber 18 to fall. The steam at the separator is 25 Kcooler. The reduced heat absorption in the vaporizer is virtuallycompletely compensated for by the convective heating surfaces of the HPpart.

This is because the flue gas leaves the combustion chamber at a highertemperature. The heat transfer coefficient resulting from radiationα_(radiation) is increased in the next heating surfaces up to theheating surface 31. The final heating surfaces 31 and 29 exhibitincreased warming-up ranges. This leads to the required outlettemperature in the MP part being exceeded by 5 K. The effects aresimilar to those when the recirculation mass flow is increased, althoughweaker. In both cases, the heat transfer in the convective part isimproved, while it is lower on the radiation heating surfaces.

If the radiation exchange coefficient of the combustion chamber 18 isincreased by 30% from 1.636 to 2.127 and the fuel, oxygen andrecirculation mass flows are kept constant, a larger heat flow isabsorbed in the combustion chamber 18, as a result of which the flue gasleaves the combustion chamber cooled down to a greater extent. Overall,a reduced heat flow is transferred in the convective part. The outlettemperature from the HP part is somewhat too high, and that of the MPpart is somewhat too low. This is comparable to the effects of reducingthe recirculation mass flow.

The effects of a change in the radiation exchange coefficient C of thecombustion chamber 18 can be compensated for by adaptation of the fuel(HP outlet) and recirculation (MP outlet) mass flows. The excess oxygenis kept constant during this process.

A reduced radiation exchange coefficient C can be compensated for by aminimal reduction of the fuel mass flow and an increase of therecirculation mass flow. It is more difficult to compensate for theeffects of a varied recirculation mass flow. It is therefore moreimportant to accurately set the circulation mass flow during generatoroperation.

The required steam parameters can be achieved in the oxyfuel process asfollows, without any changes to the steam generator heating surfaces.The heat transfer can be adapted by adjusting the fuel, oxygen andrecirculation mass flows. However, an increase in the fuel mass flowreduces the overall efficiency, and should therefore be avoided. If, incontrast, variable combustion gas compensations are used to influencethe heat transfer in the steam generator, this has a much moreadvantageous effect. The possibility of mixing in the oxygen into theprimary, secondary and upper gases and therefore of adjusting the oxygencomponent as required provides the oxyfuel process with an additionaldegree of freedom for controlling the flame temperatures. With thedistribution of the oxygen and recirculation mass flows between theburner gases and the upper gas it is possible to influence the radiationprocesses in the vaporizer via the flame temperature and the convectiveheat transfer via the flue gas temperature and flow rate. It istherefore possible to achieve a corresponding distribution of the heatflow absorption between the radiation heating surfaces and theconvective heating surfaces. The adiabatic combustion temperature in theair process cannot be reached with the same level of excess oxygen. Theeffects, in the form of reduced heat absorption in the combustionchamber because of the high temperature influence in the radiation heattransfer can be compensated for in the convective part, thus achievingthe required steam parameters.

Because of the higher density and heat capacity of the flue gas, flowspeed and flue gas temperature decrease in the oxyfuel process when thesame heat flow is introduced into the steam generator 11. The weakerconvective heat transfer which results from this is compensated for bythe higher gas radiation, because of the high CO₂ content, in theconvective heating surfaces.

This development has a positive influence on the material temperaturesof the HP part, since these depend mainly on the water and steamtemperatures because of the greater heat transfer on the inside. In theHP part, high steam temperatures are achieved only at a late stagebecause of the lower heat absorption in the vaporizer, as a result ofwhich the material temperatures are also somewhat lower than those inthe air process. The slight shift in the heat transfer toward theconvective part results in a rise in the steam temperatures in the firstMP part of the steam generator 11 by a maximum of 10 K. Because of thewide safety margins in the material design and the slightly increasedtemperatures, this is not problematic.

In the air process, the excess air is controlled on the basis of the CO₂and O₂ contents in the off gas. This procedure cannot be adopted for theoxyfuel mode because the oxygen and carbon dioxide mass flowsrecirculated with the flue gas must be included in the balance.

Increased NO_(x) concentrations are created in an air process withoutany steps by the nitrogen in the air and high combustion temperatures.In contrast, in the oxyfuel process, the nitrogen component introducedin the combustion gas is less than 7%, as a result of which virtuallyonly fuel NO_(x) can still be formed. In consequence, the creation ofthe nitrogen oxides is dependent mainly on the combusted coal mass flowand its composition. In consequence, there is no need for air steps orgas steps in the combustion chamber in order to avoid NO_(x). Instead ofthis, compositions and mass flows of the burner gases and of the uppergas can be varied in order to optimally adapt the heat absorption in thecombustion area and convective part of the steam generator to theoperating conditions. For example, during operation of the steamgenerator, the reduced heat absorption in the vaporizer resulting fromdirt can be compensated for by adaptation of the recirculation massflow.

This procedure leads to increased measurement and balancing complexity,but this can be coped with the aid of boiler diagnosis programs.

When flue gas is tapped off for flue gas circulation after theelectrical filter 13 at the point 4, the shorter flue gas lines and thehigher temperature at which the flue gas is recirculated areadvantageous. In contrast, the enrichment of the flue gas with sulfurcompounds which are still present at this point, and the sulfuric acidresulting from this, have a disadvantageous effect. In this case, heatexchangers and flue gas lines that are affected must in this case beconverted so as to be appropriately corrosion-resistant for the oxyfuelmode.

In addition, two additional heat exchangers are required inrecirculation behind the electrical filter 13, in order to reach thetemperatures at the air preheater (LUVO) 8 and before the flue gasdesulfurization installation (REA) 15.

In tie recirculation of the flue gas at the point 6 after the drier 21,longer flue gas channels are admittedly required, but, however, mostcomponents of the installation can still be used, without any change,for the air mode. The changes are limited for shutting down somepassages in the electrical filter 13, adaptation of the flue gasdesulfurization installation (REA) 15 to higher flue gas temperatures,and the construction of the air preheater (LUVO) bypass 34. Thelatter-mentioned component must be designed individually to becorrosion-resistant.

Drying the entire flue gas mass flow in the drier 21 increases theenergy consumption. Nevertheless, this results in reduced conversioncosts than in a recirculation at the point 4 behind the electricalfilter 13. In consequence, the variant with recirculation of the fluegas at the point 6 behind the flue gas drier 21 is technically andeconomically more advantageous.

In both variants the efficiency is reduced by the additional electricalconsumption for the air separation 20 and the CO₂ compression by about10%. However, the efficiency losses are small in comparison to the fluegas washing (MEA).

1. A method for operating and for controlling a power station thatcomprises a coal-fired steam generator, the steam generator beingdesigned for steam parameters that can be achieved for coal combustion,which is carried out with combustion air in the steam generator by heattransfer to the steam mass flow, wherein combustion of the fuel, whichcontains carbon, is carried out in the steam generator on the basis ofthe oxyfuel process with approximately pure oxygen, which contains morethan 95% by volume of O₂, and recirculated flue gas with a high CO₂content, such that the mass flows of all the fuel flows as well ascombustion gas flows, feed gas flows and process gas flows that aresupplied to the coal-burners and to the steam generator are formed fromcombustion oxygen and/or recirculated flue gas in their respectivecomposition ratio of oxygen and/or flue gas, and are matched to oneanother, such that the heat transfer that takes place in the steamgenerator by flame radiation, gas radiation and convection to the steammass flow in the steam/water circuit of the steam generator is kept atleast essentially the same overall in comparison to the air combustion.2. The method according to claim 1, wherein treated and/or untreatedflue gas is fed back in a recirculating manner to the steam generator.3. The method according to claim 1, wherein an existing power station isretrofitted with the method as claimed in claim
 1. 4. The methodaccording to claim 1, wherein the recirculation rate of the flue gas is65% to 80%.
 5. The method according to claim 1, wherein the flue gas istapped off after desulfurization or after a flue gas desulfurizationinstallation or a flue gas cooler, which is installed additionallyand/or subsequently, for recirculation.
 6. The method according to claim1, wherein the flue gas is tapped off after a flue gas condensationdrier in the flow direction.
 7. The method according to claim 1, whereinquicklime (CaO) is used as absorbent in the flue gas desulfurizationinstallation.
 8. A power station having a coal-fired steam generatorthat is designed for steam parameters that can be achieved for coalcombustion, which is carried out with combustion air, in the steamgenerator by heat transfer to the steam mass flow, wherein combustion ofthe fuel, which contains carbon, is carried out in the steam generatoron the basis of the oxyfuel process with approximately pure oxygen,which contains more than 95% by volume of O₂, and recirculated flue gaswith CO₂ content, such that the mass flows of all the fuel flows as wellas combustion gas flows, feed gas flows and process gas flows that aresupplied to the coal-burners and to the steam generator are formed fromcombustion oxygen and/or recirculated flue gas in their respectivecomposition ratio of oxygen and/or flue gas, and are matched to oneanother, such that the heat transfer that takes place in the steamgenerator by flame radiation, gas radiation and convection to the steammass flow in the steam/water circuit of the steam generator remains thesame overall in comparison to the air combustion.
 9. The power stationaccording to claim 8, wherein a heat displacement system is installedbetween a suction draft and desulfurization or a desulfurizationinstallation.
 10. The power station according to claim 8, wherein theflue gas channel has a bypass line that is routed parallel to an airpreheater (LUVO) and has a gas/gas heat exchanger arranged therein,after a denitrification device in the flow direction.
 11. The methodaccording to claim 1, wherein the recirculation rate of the flue gas is74% to 78%.
 12. The method according to claim 1, wherein an existing600° C. power station is retrofitted with the method as claimed inclaim
 1. 13. The method according to claim 1, wherein the same steamparameters are maintained.
 14. The power station according to claim 8,wherein the resultant steam parameters remain the same.